Moisture management in power transformers is a persistent concern especially for aging units. Extensive drying procedures are applied at the manufacturing stage and sustained efforts are deployed in service to maintain high dryness. Excessive moisture in solid or liquid insulations can lead to significant reductions of dielectric strength and reduce the partial discharge inception level. The effect of moisture on insulation aging has been well documented. It has also been demonstrated that at high temperatures, the residual moisture in winding insulation can trigger the release of free gas bubbles, thus creating an immediate threat to the dielectric integrity of the insulation structure. Assessment of water content in solid insulation is rightfully an essential part of any comprehensive condition assessment program.
A traditional method of moisture monitoring calls for oil sampling at regular intervals. The oil sample is then processed through a Karl Fischer titration method that provides the total water content in oil in parts per million (ppm). Most of the water is in the form of dissolved water and is available to move from the oil to the solid insulation as the transformer progresses toward equilibrium. However some of the measured water is chemically bound to chemical agents such as by-products of oxidation. This bound water is only partially available to migrate from the oil to the paper. As the oil ages, the quantity of chemical agents due to oxidation increases and these agents provide additional sites for the water to bind. Some of the water may also bind to particles in suspension in the oil, and this water would not be fully available to move to the solid insulation. Equilibrium curves have been developed and are used to relate absolute water content in oil to water content in paper. Application of these curves implies that the transformer is under thermal equilibrium. In fact this is rarely the case since the temperatures within a transformer are almost continuously changing based on changes in the ambient temperature and the electrical loads applied. In spite of these constraints, this method remains the most commonly used to assess the moisture content of solid insulation.
In recent years, on-line sensors for measuring the moisture content in oil have been developed. Such sensors are typically submerged in the oil and measure capacitance that is then correlated to moisture content for the oil. The moisture content in oil is then converted into moisture content in paper using equilibrium curves. This method is very approximate since it assumes that the transformer is under thermal equilibrium. However, with temperature of the transformer changing almost continuously with the variations of ambient temperatures and operational load changes, equilibrium is rarely ever achieved. Further, significant temperature gradients exist within a transformer resulting in associated variations in moisture content.
Accordingly, there is a need in the art for a system and method of determining accurate water content of solid insulation in transformers even as the temperature of the solid insulation is continuously varying. Additionally there is need to determine the water content of solid insulation at different locations within a transformer even though the water content of the solid insulation at each location may differ.